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Friend or future foe? Will L48 shale gas development help or hinder the sale of Arctic natural gas? Alan Bailey Petroleum News
Nowadays ne’er a presentation goes by on the future of the U.S. natural gas market, without a graph depicting ever expanding production from the gas shales that form continuous gas resources under vast swaths of territory in the Lower 48 states of the United States. Gas tightly held in the shale that sourced it, as distinct from conventional natural gas that has migrated into reservoirs composed of sandstone or other porous rocks, could boost U.S. gas resources sufficiently to meet the nation’s gas needs for perhaps 100 years, according to some reports.
So, does the tight gas in regional-scale rock units such as the Barnett shale in Texas, the Marcellus shale in the Appalachians and the Haynesville shale in Louisiana pose a threat to the economics of sending gas into the Lower 48 through pipelines from Arctic Alaska and northern Canada?
Not really, Mark Myers, state coordinator for the Alaska Gasline Inducement Act and former director of the U.S. Geological Survey, told Petroleum News March 24. In fact, shale gas production can provide an essential stepping stone to the future use of Arctic gas by helping expand the U.S. natural gas industry during the period prior to an Arctic gas line coming online. By assuring adequate supplies for the expanded use of natural gas, and by enabling the development of secure, home-grown, U.S. energy resources, shale gas can create a vibrant gas industry that the Arctic gas can subsequently feed into, Myers said.
“Shale gas … is our friend with respect to building capacity (for Arctic gas),” Myers said.
Increased demand Myers sees future constraints on carbon emissions as likely to drive an increased U.S. demand for natural gas, a fuel that generates less carbon per unit of energy output than coal or oil. At the same time, an increasing world population making increased use of energy-dependent technologies will drive up worldwide energy consumption, Myers said.
Modeling of global warming indicates the need for immediate and dramatic reductions in carbon dioxide emissions and natural gas can perform a pivotal role in necessary changes in fuel use, Myers said. Overall, Myers sees the possibility of an increase in U.S. natural gas demand by perhaps 14 billion cubic feet per day as a consequence of future carbon management of energy use.
In particular, Myers sees natural gas as a preferred fuel for power generation, as well as providing major opportunities for the use of compressed natural gas or gas-driven fuel cells as alternatives to more carbon-intensive gasoline and diesel to power cars, trucks and other means of transportation.
“The transportation sector is wide open for change,” Myers said.
Supply side On the supply side of the gas market equation, the evolution from conventional gas production to unconventional sources such as tight gas sands, coalbed methane, shale gas and perhaps ultimately gas hydrates, much of this coupled with the use of more expensive production technologies, represents a response to increasing gas prices, as conventional supply sources deplete, Myers said. Shale-gas production has accelerated recently and now constitutes about 5 percent of domestic gas production.
“Pretty much with any petroleum resource, you produce the conventional (resource) first — it’s the most economic,” Myers said. “… And then at a certain point in time conventional supplies aren’t adequate, so non-conventional starts playing a role.”
So, conventional, legacy gas fields, with straightforward production requirements, form the low-cost end of the natural gas supply curve, while shale gas, with its need for horizontal drilling, the drilling of multiple wells to maintain production rates and the use of hydraulic reservoir fracturing, fits some distance further up the cost-of-supply continuum.
A typical horizontal well in a shale-gas basin might cost $3 million to $4 million or more to drill, compared with perhaps $1.5 million for a conventional gas well, Myers said. And, looking at the various technologies involved, most of which have been around for several years, it is difficult to see how significant new reductions in the cost of shale-gas development could be achieved, he said.
“You’re looking for a spot for shale gas that requires a significant wellhead value to pay for the costs,” Myers said. “… It’s very price sensitive.”
Collapse in drilling And Myers cited a current collapse in drilling activity in shale-gas fields as evidence for lack of price support for shale gas development at gas prices below the $5- to $8-per-thousand-cubic-feet range.
That would place Alaska North Slope gas on the supply curve at a cost point a little below that of shale gas, even taking into account the cost of shipping the gas all the way from the Arctic to the Lower 48, especially since there has been a decline in the costs of pipeline construction materials such as steel, Myers said. And North Slope gas resources are conventional in form, thus allowing them to flow from the gas fields at sustained high rates, with lower production costs than those of unconventional gas, he said.
And while Arctic gas could flow unhindered down a future pipeline, future shale-gas production faces several significant uncertainties relating to potential environmental concerns over the possibility of drilling a high density of multiple wells in new gas-production regions; the need for major quantities of water for reservoir stimulation in some fields; and the need for new production and transmission infrastructure, to deliver the gas to market, Myers said. Additionally, unknown variations in reservoir quality and production characteristics make estimates of recoverable gas volumes highly uncertain, with shale-gas development to date taking place in relatively small areas, in the “sweet spots” where production is especially favorable, Myers said.
“There’s a lot of uncertainty around the (resource) numbers,” Myers said. “… Possibly they’re very optimistic, possibly they’re not.”
Alternative view Porter Bennett, president and CEO of Bentek Energy, a consultancy firm specializing in energy market research, takes a less bullish view of future U.S. natural gas prices and a more upbeat view of shale-gas economics.
The adaption of techniques such as horizontal drilling and hydraulic fracturing to shale-gas production, propelled by the escalating natural gas prices of recent years, has opened a door to an abundance of new gas supplies in the United States, Bennett told Petroleum News March 23.
“You’ve had a period of sustained relatively high prices,” Bennett said. “That enables producers to invest … in using horizontal drilling and fracing techniques, and also … the development of the know-how that goes with those technologies. … You’ve seen production just skyrocket in the last 18 months. … And it’s virtually all coming from shale and tight gas, coalbed methane.”
The technical innovation in unconventional gas development is disrupting the traditional gas market and, combined with the current economic recession, has led to a “perfect storm,” a game-changer situation that will affect the market for years to come, Bennett said.
Bennett said that shale gas production costs vary greatly by factors such as company and production region. He said that maturing expertise in shale gas technologies is bringing shale-gas production costs down and cited data showing major improvements in shale-gas drilling productivity over the past couple of years as one line of evidence for this phenomenon.
“These technologies are still very young,” Bennett said. “They’re still learning how to use this stuff (for unconventional gas).”
And established leaseholders in some of the traditional shale-gas basins are paying relatively low lease rates.
“We’ve done some things here at Bentek which would suggest that most of these areas can produce with prices between, say $3.50 and $5 (per mcf),” Bennett said. In fact there are producers with operational gas fields in southwestern Wyoming making money at a price of $2.50, he said.
Supply glut And the expansion of gas supply sources is causing a glut of natural gas in the United States. That glut will persist, even as the United States recovers from recession, so that gas prices will not rebound in the way that many people are predicting, Bennett said.
“In the U.S. market … supply is growing much more rapidly than demand, so you have natural market-based depression of gas prices,” Bennett said. Even using last year’s pre-recession demand levels, the United States currently has too much gas, he said.
At the same time, there are capacity constraints in the pipeline systems for delivering gas to market from some gas-production areas, such as the Rocky Mountains.
“The pipeline constraints limit the ability of the region to export production at a level that is lower than the region’s intrinsic ability to produce,” Bennett said. And that causes downward pressure on prices in the production basin because of competition between producers for that export capacity.
But the balancing act between downward price pressure as production levels hit export pipeline capacity, and upward price pressure as subsequent cuts in drilling cause production to fall below that capacity, will constrain the price range, Bennett thinks.
“That’s why prices in the Lower 48 are going to be kind of range bound in our opinion,” Bennett said.
Uncertain future However, factors such as the Obama administration’s policies on future oil usage and carbon emissions could increase gas demand. That could elevate prices by a modest amount. But the increased use of gas has to happen on the “right side of the (delivery) constraint to be effective,” Bennett said.
On the other hand, nobody knows what the price of gas will be in 2020, the likely timeframe for a North Slope gas line coming online.
“You can’t make decisions right now with any concrete knowledge of what the market’s going to look like,” Bennett said.
The critical point is that people need to pay close attention to how the gas market is evolving, to evaluate how market changes will impact the gas line project, he said.
“You’ve got to recognize that there is at least the possibility that the Lower 48 supply situation will make the absorption of Alaska gas difficult,” Bennett said. That might argue for maintaining the opportunity to export Alaska gas as LNG, to leave open the option of exporting the gas to foreign markets such as Asia, he said.
“You’ve got to explore both options … recognizing all the while that the market may work against you,” Bennett said.
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